Hydraulic fracturing, gravel packing, or fracturing and gravel packing in one operation, are used extensively to stimulate the production of hydrocarbons, water and other fluids from subterranean formations. These operations involve pumping a slurry of “proppant” in hydraulic fracturing (natural or synthetic materials that prop open a fracture after it is created) or “gravel” in gravel packing. In high permeability formations, the goal of a hydraulic fracturing treatment is typically to create a short, wide, highly conductive fracture, in order to bypass near-wellbore damage done in drilling and/or completion, to ensure good communication between the rock and the wellbore and to increase the surface area available for fluids to flow into the wellbore. Gravel is also a natural or synthetic material, which may be identical to, or different from, proppant. Gravel packing is used for “sand” control. Sand is the name given to any particulate material, such as clays, from the formation that could be carried into production equipment. Gravel packing is a sand-control method used to prevent production of formation sand, in which a steel screen is placed in the wellbore and the surrounding annulus is packed with prepared gravel of a specific size designed to prevent the passage of formation sand that could foul subterranean or surface equipment and reduce flows. The primary objective of gravel packing is to stabilize the formation while causing minimal impairment to well productivity. Sometimes gravel packing is done without a screen. High permeability formations are frequently poorly consolidated, so that sand control is needed. Therefore, hydraulic fracturing treatments in which short, wide fractures are wanted are often combined in a single continuous (“frac and pack”) operation with gravel packing. For simplicity, in the following we may refer to any one of hydraulic fracturing, fracturing and gravel packing in one operation (frac and pack), or gravel packing, and mean them all.
It is very undesirable to allow the proppant or gravel to pack the wellbore above the producing formation. If this happens, the wellbore must be cleaned out to permit various other downhole operations, such as placement of tools, to permit optimal fluid production. It is also very undesirable if the operation screens out too late or not at all, that is if the fracture keeps growing, in length and/or in height, beyond what is necessary and desired, and an optimal pack and desired fracture size and shape are never generated to maximize production and to prevent flowback of proppant or sand.
As mentioned, short, wide fractures are often desired. The most common method of creating short-wide fractures is to initiate a tip screenout during the pumping operation. In a tip screenout, the solids concentration at the tip of the fracture becomes so high due to fluid leak-off into the formation that the slurry is no longer mobile. The concentrated proppant slurry plugs the fracture, and prevents additional fracture growth. Additional pumping of the proppant/fluid slurry into the formation after the screenout causes the fracture to grow wider, and large concentrations of proppant per surface area are placed in the fracture. The design of these treatments relies heavily on knowing the correct mechanical properties, permeability, reservoir pressure and fluid saturations of the formation being treated. Prior to most of these treatments a small fracturing treatment (sometimes called a “data frac” or “mini-frac”) is performed in order to measure these properties and to determine the formation's response to a hydraulic fracturing treatment. Treatment designs are often modified on the fly to incorporate this new information. Important design parameters are the size of the pad, the size and number of stages, and the proppant or gravel concentration in each subsequent stage, and the nature of the fluid and additives used in each stage. Treatment design and modification is typically done with the aid of a computer model, many of which are available in the industry.
The pad is the proppant-free fluid pumped to initiate and propagate a fracture before stages including proppant or gravel are started. It typically serves another purpose as well. It lays down a coating, called a “filter cake”, on the faces of the forming fracture. This filter cake reduces the flow of fluid from the fracture into the formation (affecting the “efficiency” of the job (see below)). The filter cake may be formed from the viscosifying agents that are normally present, such as polymers. The filter cake may also be formed by adding additional materials to the fluid for that purpose, especially if the pores in the fracture face are large. Such optionally added materials in this use are often called fluid loss control additives, or FLA's.
In hydraulic fracturing, in particular in low permeability formations where the longest possible fracture is desired (in order to create the largest possible fracture face for flow of fluids into the fracture and ultimately into the wellbore), modes of operation that might induce a tip screenout are typically avoided, in order to achieve long, conductive fractures. If a tip screenout is encountered in such a fracturing operation before the entire designed treatment is pumped, as inferred from an increase in pumping pressure, the pump rate is reduced or most likely the treatment is stopped and considered a failure. We will call hydraulic fracturing job designs and job executions in which a tip screenout is not desired and does not occur, “conventional” hydraulic fracturing.
On the other hand, sometimes tip screenouts are desired. Design features typically employed in those special situations in which a tip screenout is desired typically involve methods of ensuring that fluid leak-off is high relative to the rate and amount of proppant injection. This can be achieved by using a small pad, using little or no fluid loss additive, using higher proppant concentrations earlier in the treatment, pumping more slowly, and other methods known to those skilled in the art of fracturing and combined fracturing/gravel packing.
Unfortunately, in spite of data-fracturing information, the pressure transients collected by downhole pressure gauges during treatments indicate that TSO's do not occur in many, perhaps the majority, of the treatments in which they are desired and intended. The fluid at the tip of the fracture remains mobile, the fracture tip continues to grow throughout the treatment and the desired proppant concentration in the fracture is not reached. Therefore, the desired fracture conductivity is not obtained. Often, TSO's have to be coaxed by lowering pump rates or increasing proppant concentrations when the TSO is desired.
There are two principal reasons for not achieving an appropriate TSO. First, the fracture may be too large for the proppant volume. This occurs a) when the pad is too large or b) when the “efficiency” is too high, or c) when the ratio of proppant volume to slurry volume selected in the design of the job is not high enough. (The “efficiency” in a fracturing operation is high when fluid leak-off is controlled—either naturally by the properties of the fluid and the matrix, or by the addition of fluid loss control additives—to an acceptably low level; efficiency is low when leak-off is high, so that very large volumes of fluid must be pumped in order to generate the intended fracture size and shape and to place a specified amount of proppant or gravel.) Second, the fracture width may be too great for the proppant to form a bridge in the fracture. This may be due to bad initial design (for example in choice of proppant diameter) or to width growth beyond what was expected.
Up until now, besides designing the job better, the major way to deal with these problems was directed towards optimizing the choice of fluid loss control additive or additives and the stages of the job in which they were used, especially if the main problem was that the fracture was too large for the proppant volume.
Fibers are used in fracturing to control proppant flowback. In that case, fiber is added at an optimal concentration to control proppant flowback, while not significantly impacting fracture conductivity. If one is using glass fibers, for example, this concentration is approximately 1 weight per cent by weight of the proppant. This concentration is insufficient to cause bridging during pumping under the conditions at which it is normally employed, especially in low permeability formations. Fibers are also used sometimes to aid in transport of proppant when the viscosity of the fluid is very low. Tip screenout is commonly deliberately avoided in these treatments; proppant concentrations are kept low through careful pre-treatment job design, especially in careful selection of pumping schedules. For example, in these treatments the pad volume is increased over conventional job designs to ensure that sufficient fracture width is generated prior to the proppant/fiber slurry entering the fracture. However, U.S. patent application Ser. No. 10/214,817 (assigned to Schlumberger Technology Corporation, filed Aug. 8, 2002, hereby incorporated in its entirety by reference) describes a method of deliberately using fibers to enhance tip screenout when desired.
The ability to achieve success in obtaining TSO's is very uncertain in significant part due to the fact that the true nature of the subterranean formation is unknown and variable. It would be highly desirable if a method were available to induce a TSO when needed that depends more upon features of the job under the operator's control (especially the chemistry of the fluids and fluid loss control additives used) than on the unknown variability of the formation. There is a need for a more reliable way to ensure that intended tip screenouts will occur and to allow for more flexibility in design of tip screenout treatments.